Battalion Oil Corp (BATL) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2008 RAM Energy Resources, Inc. earnings conference call. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today, Mr. Bob Phaneuf.

Good afternoon. Thanks for joining us on the RAM Energy Resources conference call to discuss our first quarter 2008 operating and financial results. With us today are Larry Lee, our CEO; Les Austin, our Senior VP and CFO; John Longmire, Senior VP; Sabrina Gicaletto, our VP and Controller; and me, Bob Phaneuf. On our agenda for the call today we're going to have a review of the financial results and our operating results through the end of April, as well as a current update regarding the status of RAM's outstanding warrants, and then we'll go to Q&A. Before we begin let me read our Safe Harbor statement.

In our call today we may make statements that are other than historical facts. Information in the presentation and all such statements that refer to managements plans or expectations, including capital spending, drilling plans, derivative positions, interest expense, G&A expense, and other industry conditions are forward-looking statements within the meaning of the Securities Exchange Act of 1934. The Company cautions that such forward-looking statements are necessarily based on certain assumptions, which are subject to risks and uncertainties which could cause actual results to differ materially from those indicated today. Further information on these risk factors is included in the Company's filings with the SEC, as well as at the beginning of the Webcast slides. Management of RAM encourages you to review the disclosure in both of these documents.

With that preamble, I'll stop there and turn it over to Larry.

Thank you, Bob. Welcome, everyone, to our first-quarter call. I think the quarter turned out much as we had expected. Our volume was up 96% to 612,000 barrels equivalent. We had earlier indicated we thought that number would be right around 600, or maybe 605, and we were actually able to beat it a little bit. Our average daily production was 6725 BOE, and that's up of course significantly from the 3478 BOE in the first quarter of last year.

Also our first-quarter production was 40% up from our fourth-quarter production. And of course this is the first quarter where we've had the full impact of the Ascent acquisition in our numbers. And so we had really a very nice quarter. Oil averaged $96.17, which was up 71% from the same period a year ago. NGLs were up to $53.99, or about 42%, and natural gas was [7.54], up 21%. So on a total BOE basis, $71.13, which is up 47% on a BOE equivalent from the same period a year ago. On a realized basis, our oil was the only thing that really suffered any reduction as a result of our derivative position, and our net to realized oil price was $88.39. Derivatives had no impact on our realized natural gas liquids or on our natural gas. And our overall BOE on a realized basis was $67.34, which is up almost 40% from the same period a year ago.

And with that, I'm going to ask Les to go through some of the financial highlights for the first quarter for us.

Thanks, Larry. I guess I'll start out by talking about the production, up significantly, and prices combined to drive our oil and gas sales up to $43.5 million, which was 188% increased over last year's revenue of about $15.1 million.

RAM did report a loss in the quarter of about $0.01 a share, or $523,000, principally as a result of the unrealized losses that Larry spoke about previously; they were $5.3 million in the quarter. Excluding those derivative losses, the Company would have realized $2.7 million of net income, or $0.05 per share.

Cash flow for the quarter was very positive, $16.2 million compared to the $4.1 million in the same quarter in 2007. That represents operating cash flow per share of approximately $0.28 versus $0.11 in the first quarter of 2007.

EBITDA for the quarter was up to $24 million. That's versus $7.8 million in the first quarter of 2007. And the capital spending was about $13.2 million, which was in line with our estimates. We still expect to spend our full capital budget of $8 million that Larry will discuss in more detail later.

Also, as discussed in the press release, G&A costs were up to $5.5 million in the quarter, which included approximately $853,000 of professional fees associated with our year-end financial reporting. We are now accruing ratably over each quarter of the year those costs for the current year. And we expect that our G&A costs for the balance of the year will range between $4.7 million and $5.2 million each quarter.

Thanks. (inaudible) run everybody through our growth projects, because we think we're starting to see results from this area. We did drill and we began production of two wells in our South Texas play. We have one well that is currently completing and we're getting ready to spud the fourth well, and then we'll have five more that we'll drill throughout the year. We will continue to have one rig working in South Texas for this year.

Activity in our Barnett area has really begun to accelerate nicely. At the end of the quarter we had 15 wells that were producing. We had three wells that were completed during the first quarter. We had three wells that were spud during the quarter that are either currently producing or awaiting completion. And then we've got three wells that have been spudded so far in the second quarter. We still have another well that will follow up on that that we already had proposed. So we're really seeing an acceleration of the activity in the Barnett, and I'll get into a little more detail in that in a few minutes.

West Virginia is getting ready to kick off. The rig that we contracted for has just completed drilling the well that it was on. It is being moved, and we'll spud this well in just as soon as we can get the rig moved to the location and started. We've continued to work on getting our additional wells permitted there, and I'll get into a little more detail in West Virginia. But I think the key thing I would leave you with is that our sort of production growth drivers are all moving forward, and I think we'll begin to see even more results in the second quarter from those.

Our production maintenance projects -- these are primarily our big oil fields in North Texas and Southern Oklahoma. We did drill 16 wells in Electra/Burk with our rig. We've got another 150 PUD locations. And we're beginning to do a lot of the recompletion work that I have spoken about in earlier periods, where we've been looking at recompletion of existing wellbores, be they either temporarily abandoned, or zones that have not previously been open. So we're pleased that we were able to get that project started; we've been working on it now for about seven or eight months from an engineering standpoint, and we're now beginning to implement that.

In Fitts and Allen, we had our first two wells that we drilled, and we're producing in the first quarter. One well is completed, one well is currently drilling. And once again we'll discontinue to have a rig working in the Fitts Allen field for this year. We do have 57 proved undeveloped locations in that field force as well. And just to put it in perspective, Electra/Burk produces about 1700 barrels of oil a day to us, and Fitts and Allen produces about 1300 barrels a day. These two fields are producing close to 3000 barrels a day of oil for us. And we're -- today we were selling it for about $123 a barrel in the field, which is sort of hard to imagine.

Rigs under contract. We've talked about this in the past, but we will have a rig working all year in Fitts Allen; we'll have a rig working all year in Electra/Burk; looks like we're going to have a rig working all year in Barnett Shale; South Texas we'll have a rig working full-time. And as soon as we spud this first well in West Virginia, then that well will stay under our contract for the balance of the year.

As Les said, we spent $13.2 million in the first quarter. Our budget for the first quarter was 13 million, so we're very much on target with this as far as initiating the drilling program. A lot of this was of course on the Ascent asset that we acquired, and we continue to be very pleased with the initial results on that.

In an effort to try to give the market as much current information as we can, on these next few slides we've tried to update these all the way through May 1st, not just through March 31st. Through May 1st we have drilled 31 wells; 23 of them were producers, we had eight that were in various stages of either drilling or completing at the end of April. So far we continue to move ahead with our drilling program, and we clearly expect to spend the $80 million that we have budgeted for this year.

If we look at South Texas, we drilled the Garza Hitchcock 12, which we were able to get in production right at the end of last year. And so far in the first quarter we did drill three wells. We drilled the Garza Hitchcock 13. It's been the best well we've drilled there so far, came in at 3.2 million today. And that well went on sales on February 5th. So we were able to get some benefit of it in the first quarter. The Garza Hitchcock 11 we completed at about 2700 Mcf a day, and that well went on sales on April 15. So we didn't get any benefit of it in the first quarter, but we will get some benefit for it in the second quarter. The Garza Hitchcock 14 is now completing. We're just in the process of drilling out. We've recently fracked the third stage in it, and we're drilling out the plugs, and I expect that well would go on sales sometime later this week. And then our next well that we spud will be in our Wilcox play, and that rig is due to show up and spud it at any time. Once again, these are 100% working interest wells. (inaudible) about 75% net revenue. So these wells really should begin to show nice production growth as we move into Q2 and Q3.

In the Barnett area, at the end of the quarter we had 15 wells producing, one completing, two awaiting completion, two wells that we're drilling, one more to drill immediately after that, and it's possible we'll have some follow-on from that. We do still have roughly 29 locations that we've identified seismically. We had a CapEx program of $10 million for this program. We've already committed that much money for this year. We will be evaluating the amount of capital that needs to go into the Barnett, and most likely be making an adjustment to the capital program, increasing that sometime in the second quarter, or certainly by midyear is normally when we reevaluate our capital plans. But at this point it looks like we will be spending more than $10 million in the Barnett play.

If you look at page 12, it shows the Rawle/Burress lease. That well -- we really are starting to begin to see some nice results here. And the Etta Burress 2H and the 4H, that was our [simulfrac] wells, they were shot-leg horizontals, 500 feet apart. The combined rate for those two wells was 3.1 million a day, and we ended up spending 1.8 million to drill the 2H, and about 1.9 million to drill the 4H. Those two wells went on sales lines; the 2H went on March 24th, and the 4H went on sales on March 21st. So we got a little bit of production in the first quarter from those two wells, but not a significant amount because they didn't get hooked up to the sales line until fairly late in March. The Etta Burress 3H which we drilled was completed at 3.7 million a day. It was almost a 2800-foot lateral leg on that, horizontal lateral on that one. That well went to sales on April 15. The Molloy 1H is currently completing. And I think we're currently on the third stage of the frac on that well. The TL Dickenson A4H and the A3H have both been drilled and are awaiting completion. We are currently drilling the TL Dickenson A5, and then we will move over and drill the TL Dickenson A2 well. So we've had quite a bit of activity going on in sort of the western half of this Rawle/Burress lease. And if you look at slide 12, you can see we have some additional (inaudible) possible locations we've identified seismically. So I don't think we're through drilling on this piece of acreage by any means. If you look at it on an acreage to wellbore basis, this is at about 109-acre spacing. So we think we've probably got a few more wells to be drilled here in the Rawle/Burress area.

In the Barnett Shale, or EOG jointly owned acreage, we've got three wells that are producing. The Brown 2H well is currently drilling -- here it says we're currently drilling. We've actually now reached TD. We have set casing on the vertical leg, and we have logged the horizontal leg. This is about a 2000-plus-foot horizontal leg, and this is a well that we own 89% working interest in. So we will be anxious to complete this well and see the results of it. We do have about 37 square miles of 3-D here. We're continuing to work the seismic, evaluate the drilling location in this general area, and we're kind of excited to get some more action kind of on this part of our acreage in Wise County.

If you look at the West Virginia play, this is a play we're very excited about in that we do own 100% of it. We've got 45,000 net acres. This gives us well over 500 potential drill sites, assuming 80-acre spacing. The rig is in the process of moving in, so we're going to get this well, the first well spudded here pretty quickly. And I've been doing a lot of research, looking at some of the other players in the area. In addition to Cabot, which I've talked about before, Equitable Resources is our neighbor, as is Penn Virginia up in the north, and a couple of private companies. I think it's interesting to note that both Equitable and Cabot are using anywhere between 0.75 Bcf to 1.5 Bcf of recoverable reserves per wellbore in all of their presentations. As I think I've shared before, we're using 0.8 Bcf per well, and both Equitable is assuming a $1.2 million drill and complete cost; Cabot has been saying about $1 million to drill and complete; and we've used 1.3. So I think our economic projections are very conservative and very much in line with what we're seeing from both Equitable and Cabot, which are old-line Appalachian players. So we'll begin to drill in the [cornstalk] area where we have our gathering system and our market for the gas. So we'll be anxious to share with the market the early drilling results, and I would hope we would have something we could begin to share with the market as we move into the latter part of the second quarter, or certainly by the early part of the third quarter.

So operationally those are kind of the highlights. I think we are on track with our plan. And with that, I'm going to turn it back to Les to talk a little bit about the liquidity.

Just a brief comment or two on liquidity. On February 15th we repaid the senior notes, which reduced the high-interest debt that we had on that, and replaced it with revolving line debt. We currently have about $351 million outstanding on our term note and our revolving debt at March 31st. With the cash on hand, that leaves us with about $39 million of total liquidity.

A brief comment on the warrants outstanding. There are currently about 18.8 million warrants outstanding. 100% exercise of all warrants would generate about $94.2 million of cash, which we would currently use to repay some of that debt.

There's also a note on page 16 about our interest rates. We had about a $2.5 million interest cost for the month of March. That's down sequentially from the first two months' average of $2.8 million, about $350,000 a month, or about 12%.

Thanks, Les. Once again, I think our valuation continues to lag behind any reasonable measure of the asset value that this company has. I think the fact that the warrants will expire at 5 o'clock Eastern Time on Monday, and I personally believe that the warrants have had some impact on the inability for our stock to get out of this $5 price range. So I think come next week, that will be behind us. We should be able to report to the market the result of the warrant exercise probably sometime by the middle of next week. And once we have confirmation from Continental Transfer on how many of the warrants, if any, get exercised, we will certainly make that available to the market, probably through a press release.

Once again, before we go into Q&A, I think we've got both production growth drivers in this portfolio of assets we own, both conventional and unconventional. We've started the program, I think, well as far as getting the rigs under contract and getting the wells drilling, and beginning to see the production coming in. We do have this long-life oil base that provides a very stable amount of cash flow for us. We continue to be 60% crude oil and natural gas liquids on a production basis. I think as we move forward, you'll see a little more natural gas in the portfolio. But we think we'll continue to have a very substantial part of our production base be oil and natural gas liquids. We think we've demonstrated we can create value with the drill bit or through acquisition. And once again, management continues to own a significant piece of this company and, I think, is working very hard to try to get our inherent value recognized in the marketplace. And we will be continuing to work on that, and get out and tell our story as we move into the future.

So I think with that, Bob, we're ready for Q&A.

(OPERATOR INSTRUCTIONS). Neal Dingmann, Dahlman Rose.

Larry, are you happy now -- you gave a pretty good -- obviously, good update on a lot of the areas. I'm just wondering, on the Barnett Shale area, are you content now with the pace of activity you're seeing there?

Yes, I am. Remember we talked last year that we collectively, Devon and us, were in the process of unitizing that lease so we could accelerate the drilling? Clearly that's what's taken place. And we are very pleased that we're able to kick off some more drilling on the EOG-owned acreage as well. I think we're going to start to see some more activity there. I do think we'll probably need to revisit our capital allocation for that asset.

On the Appalachian, it sounds like you pretty well sit, at least near-term (technical difficulty) would any results change that as far as make you more active, make you bring another rig on, or is that pretty well set here, at least near-term?

Which area was that?

In the Appalachian area (multiple speakers)

Our thought all along is that we've got to get these first wells drilled, and kind of get some history for ourselves. I like what I'm seeing out of Equitable and Cabot and others, but we need to get in there. Clearly, with as much acreage as we have, that will be a multiple-rig area for us as we move forward. I think we've got this rig contracted for the balance of this year. I would suspect that rig would probably be working for us for the next several years. And we would be looking at adding more rigs to it as we move into the year, or certainly as we move into '09.

Lastly, on the Fitts Allen side, sounds like it will kind of be steady there. Is that fair to say, or do you foresee there could be some upside on top of that?

I think there could be a little bit, but we're not really forecasting it or counting on it. We're really looking at Fitts Allen and at Electra/Burk to just kind of maintain their production levels. The cash they're generating is enormous at these prices. The average cost to produce that stuff is about 18, $19 a barrel. And in this environment we're selling it for tremendous margin. So our thought is we -- at the work level we have there, we kind of see those staying steady. There might be a little bit of upside in Fitts Allen from an operational standpoint, but we haven't budgeted any of that at this point.

(OPERATOR INSTRUCTIONS). Ron Mills, Johnson Rice.

A follow-up on the West Virginia. You mentioned you were going to focus your initial activity in the cornstalk area due to infrastructure issues (inaudible) being available. Can you walk through the infrastructure available in that area, and how it applies to the 14-well program? I want to make sure all 14 of those you expect to be horizontal.

We expect everything we're going to drill out there is going to be horizontal. The reason we're beginning our program in the cornstalk area is we own our own gathering system there, and these wells will be air-drilled and nitrogen foam fracked. So you've got to get the nitrogen out of the gas stream before you can get it into the interstate system. We have a contract with a polymer plant that our gathering system feeds into. And that polymer plant is able to take the gas stream with up to 20% nitrogen in it, which is a critical point for us, that as we drill these wells and frac them, we don't just have to vent them to clean them up, or to -- we don't have to wait to get enough nitrogen rejection units hooked up to be able to produce them. So that was a major sort of breakthrough for us in kicking off the West Virginia program. That plant can take up to 9 million a day. So our plan -- and we have a nitrogen rejection unit on order -- our plan would be to expand off of our gathering system, take the nitrogen-rich gas and sell it through the polymer plant until such time as the wells clean themselves up, and then begin to divert that gas into the interstate system. As we drill new wells, they will then go into the polymer plant. So it allows (technical difficulty)

Hello?

Ladies and gentlemen, we have a technical difficulty. Please stand by.

Ron? We had a technical difficulty. Somehow the line just dropped us. I don't know what happened.

I don't know either. I thought maybe you got tired of talking to me.

Sometimes.

Where you dropped off is once the wells clean up and you (inaudible) take them to the interstate system --

We've already applied to Columbia for a tap into the Columbia line, which runs right along our property. This will allow us to get some early production results and some early sales, even though we will be selling it at a discount. We're only going to realize about 75% of index, but it allows us to begin to get these wells cleaned up, get some sales information, and get some production history on how quickly these wells will clean themselves up from the nitrogen that we put in. The formation doesn't have nitrogen; it's just what we're putting it in with the frac we've got to clean out before we can ultimately get it into the interstate system.

Given your 100% working interest in the productivity of the South Texas wells, and your fairly extensive inventory in that play, I assume that area can become a fairly significant growth driver for you all as we look through the remainder of the year and into 2009. Are those -- is that a more gassy production stream than --?

Yes. One thing, in South Texas we get quite a bit of condensate with that. But this is essentially a gas play, as you know. We're not expecting much in the way of liquids at all in West Virginia at this point. It looks like maybe this gas is around 1040 BTU, based on some of the samples we've seen off of the vertical wells we have. So what we're expecting is that those growth areas -- and even the stuff we're bringing into the Barnett is gas -- you're going to see more gas production coming into the mix as we go forward. So as a percentage basis, our oil and NGLs is probably going to start going down percentage-wise, but we think they'll end up staying relatively flat in terms of the absolute volumes they're producing right now.

And is the South Texas play on a one-rig plan?

Yes. It's a one-rig plan.

I'll jump off and jump back in line. Thanks.

Barry Sahgal, Gilford Securities.

Would you give us some color as to your strategy and thinking about hedging in this rather robust commodity pricing environment? And perhaps as an add-on, could you go through what your current hedging position has been, and what we should be looking for going forward into the balance of '08 and '09?

Good question, and there is -- one of the slides in our presentation gives our current hedge position, and we actually break it down by quarter. I have to say that in this current environment, we are no longer doing any collars. We're only buying floors at this point.

If you look at -- for the second quarter, we had 1500 barrels a day that has a ceiling of $83.13. So that's all of the ceilings that are imposing price limitations on our oil as we move into Q2. And Q3, it's $84.80, also on 1500 barrels. Q4, it's $83.06 on 1500 barrels.

The thing that we did in anticipation of the Ascent acquisition is we went into the market and bought a bunch of floors in the $70, $72 range. And that's what we've been doing, is picking up floors in that 70 -- and of course now, probably, if I buy one today for $1, I could probably get a $90 floor right now for '08, and I could probably get a $75 floor for '09 for about $1. That's kind of how we're approaching it now. We're continuing to try to layer in additional floors, and not put tops on them at this point in time. I don't know whether Goldman is correct or not, and we're going to see a super spike, but that's kind of our philosophy.

Our credit facility requires us to hedge between 50 and 80% of our production. On a blended basis right now, I think we have about 56% of our production that is hedged. And what that is is it's your PDP forecasted production. You don't really add the PUDs, or probables, or any additional production coming from drilling. And it's a rolling 30 months, John reminded me. We're always adding new positions each quarter as the current positions roll off.

And the floors count in that 50 to 80% range, right?

Yes. Historically, when I put those $65 by $83 collars on, that looked pretty smart. But, hindsight says differently. I would have been wiser to have bought the floors like I did for -- the bare floors that we have in '08 and '09, and we've even got some secondary floors in the first quarter of 2009. We're trying to make sure we comply with our lending covenants, but by the same token, not close ourselves out on some of the upside runs in the commodity price.

A slightly different question, which is on West Virginia. Is there much open acreage, or deal-driven acreage that you could participate in in that area?

We believe that there is, and we're working on it diligently.

I won't push you further. Thanks for the answers.

Ross DeMont, Midwood Capital.

If we look at where production was in the first quarter, should that represent sort of the baseline of production for the rest of the year, and your drilling results will more than offset declines? I guess what I'm kind of hoping for is you'll help us understand what the production growth rate could look like throughout the year.

We're not yet giving production guidance. On the fourth quarter call I told everyone I thought we would produce about 600,000 barrels in Q1; we did a little bit better than that. I think for Q2 we're expecting to produce somewhere around 630 to 635,000 barrels.

We do think that as we drill, we'll be able to grow the production 2, 3, maybe 4% sequentially here for the next couple of quarters. And of course we're not forecasting any real production out of West Virginia, although we think we're going to get some. We have our internal forecast, and we were able to beat it in the first quarter. That's one of the reasons I gave you those dates of the wells that we drilled. A lot of what we drilled in the first quarter didn't really come online until late in the first quarter, and some of it didn't come online until early in the second quarter. I think as we continue to accelerate the drilling in Q2, we'll begin to get the benefit of production from Q1 as well as the wells we can get on -- I think our forecast is to jump it up to about 15 or $16 million invested in Q2, and then it jumps up again in Q3, and again in Q4, to get to our $80 million budget.

We did have a board meeting today following our annual shareholder meeting. And given what commodity prices are doing for us, we will probably be revisiting our capital budget sometime in the second quarter. You look at the first quarter, we generated $16.2 million of internal cash flow, and we invested 13.2 million. So we're seeing, obviously, an increase in cash flow as a result of these higher prices, and that probably put us in a position to maybe consider increasing this capital program as we move forward this year.

In terms of realizations, as I'm looking into the second quarter here, is there any reason to think that realizations (technical difficulty) wouldn't be higher in the second quarter?

They definitely will, because prices at the end of March -- let me grab my sheet -- was about -- I've got it right here -- oil prices at the -- average price for the month of March was $105. The average for April was $112. The average so far for May is probably closer to 116 or $118. (multiple speakers) as those prices go up, our -- fortunately it will mostly be in the form of unrealized mark-to-market. But I suspect you're going to see the entire industry continue to post larger unrealized mark-to-mark derivative losses as we move into Q2 and Q3 if these prices continue to run like they are.

That's fine. That's really all I had. I just wanted to make sure production is going (technical difficulty)

[Ross Taylor], [Cheshire Capital].

Most of my questions have been asked by the previous two questioners, but I wanted to get into the question -- I understand you're looking at unwinding or taking off the ceiling side of your collars. Is there going to be an economic expense in the second quarter to that? It appears that you did -- perhaps did some of that in the first quarter, and realized some losses in those trades.

What those are are the -- each month, some of those trades are coming off and we're settling up with our counterparty. And that's what's driving the realized number. I think we had -- what was it, Les -- $2.3 million of realized derivative losses, and that's what we actually paid to our counterparty. And that takes place every month. In fact, the check we sent them, I think, this week was $1.3 million for the most recent month, for the month of April. So we are working these off. If we wanted to take the ceilings off, it would cost -- we would have to buy (inaudible) at whatever the mark-to-market calculation is. And we continue to monitor the commodity markets to look to see if there comes a time that it makes sense to sort of bite the bullet and take some of those hedges off, or whether we're (technical difficulty) let them roll off as they mature.

You mentioned earlier about 1500 barrels basically capped or ceilinged out at this point in time, and that looks like it's rolling that way for the next (multiple speakers) what's the rolloff rate on the 1500 barrels?

1500 barrels a day for every day, all the way through the end of this year.

Okay. Is there anything capped out for next year?

Yes. In the first quarter of next year we've got 2000 barrels -- and this gets a little bit complicated, because -- 2000 barrels at $82.63, 15,000 barrels in Q2 at $81.07, 1000 barrels at $81.22 in the third quarter, and 1000 barrels at $82.50 in the fourth quarter. But then in the first quarter of next year, we have a secondary floor, where we move back in on 800 barrels at $75. So, you really don't have 2000 barrels a day with the cap; you really have 1200 barrels a day capped in Q1 of '09.

It's on page 21, the detail of it, in our slide presentation, which is on our Web site if you want to get down to look at the detail. I think that will kind of help you. And I would say that probably we have one of the -- we're not as heavily hedged, I don't think, with ceilings as some of our industry partners, at least in the small cap side of the world. We're producing about 3500 barrels of oil a day, so we're limited in the mid $80 numbers on those 1500 barrels, and the rest of it we're getting market price for.

I appreciate the color. And I think that, obviously, the [information] on the Web site is very helpful. Thank you.

(OPERATOR INSTRUCTIONS). Leo Mariani, RBC Capital Markets.

A question in terms of what your thoughts are on the Devon Barnett program going forward. Obviously, they've got a number of wells in various stages of progress here. Have you had any sidebar conversations with those guys, and you suspect that their activity levels may continue all through the end of the year in terms of what they're doing? Or what's your thoughts there?

Everything that we -- we think they're going to continue at a high level of activity. We think there are some more -- clearly, there are some more drill sites on the Rawle/Burress lease, and then we own a couple of other leases with Devon that we would expect that we would probably move to and begin to see development on once we've kind of drilled up this Devon, this Rawle/Burress area.

The nice thing about the Rawle/Burress area is that we've got pipeline connections. We drill these wells and immediately flow them to sales, taking them into the Bridgeport plant that Devon owns. So that's why our activity level has been so concentrated in this Rawle/Burress lease, because it's just a great place to take the gas to market. We've also had very good results in this play. So I don't really think I'm going to see too much of a slowdown out of Devon, based on kind of staff-to-staff discussions we've had.

Give us a semblance, if you guys have it, of how many locations you may have on those couple other leases. Where are they, and what's the infrastructure situation there?

I don't have that right here in front of me. Hang on a second. I can give you (inaudible) pretty good idea. We have about 3600 gross acres with those guys, and this Rawle/Burress lease -- I don't have it. We've got two other leases that probably together are about the same size as the Rawle/Burress lease. This is probably about half of our -- approximately half of our jointly owned Devon acreage.

Well, I guess, switching gears, I just want to get a little bit more clarification on your debt level over there. I guess you guys were somewhere around $350 million at quarter-end. How much of that is in a revolver, and how much of that is in the term loan piece that you guys have out there? And what are the rates on this?

200 on the term. LIBOR plus 750. The balance of it was on the revolver at LIBOR plus 175 to 2. I don't remember; it's one of those two.

So we're paying about 4.5% on the revolver and 10.25 on the (inaudible)

Remember, to the extent that we get a significant exercise of the warrants, we have a no-cost clawback under the expensive part of that debt facility, if that's where we would choose to put it. So we're anxious to see how many of the warrants get exercised, what's the net proceeds from the warrant exercise, and then we'll evaluate where we want to put that. If we need it to accelerate the drilling program, that could be maybe part of it, or we may put it -- we may put some of that cash against the expensive part of our debt.

Is that clawback pretty limitless? You guys can (multiple speakers)

Up to 100 million. We knew we had the warrants expiring, we knew it was at $95-plus million, and our lenders were nice enough to work with us to allow us to have that free clawback for -- I think it's up to $100 million out of the exercise of the warrants.

Any plans for any noncore asset sales (inaudible) you guys pay down any debt?

Yes. We've got a few small deals kind of in the hopper that we're negotiating on, but nothing that we've inked or announced. We're looking at some of the -- kind of some of the nonoperated stuff, and we continue to look at East Texas as a possible something we might get out of. We've got 1200, 1800 acres, something like that, in the Woodford (inaudible) and Southeast Oklahoma. We don't really operate any of that. We may get out of that. So, we're looking at -- I'd say we're looking at probably three or four areas where there are assets that we either owned before the Ascent merger, or assets we acquired in the Ascent thing that are really not critical to us from a long-term standpoint.

Thanks.

Ron Mills, Johnson Rice.

Larry, do you have the same 36% interest in those other two leases with Devon?

Yes. Devon owns 50, we own 36, and then the other -- Ted (inaudible) basically owns the balance of it.

On the South Texas side, just to make sure, particularly as it related to Ross' question on the production, with South Texas and the wells coming on the way they do, I understand the hyperbolic nature of those declines. But, is that an area with some potential upside to drive production relative to what you provided?

Yes. I would point you back to our slide, which is number 10. We have 18 PUDs. But then in addition to that, we've got 13 probables and 39 possibles. Our whole strategy was if we continue to be successful as we move south and east -- you can kind of see the little map, and you can see the probables and possibles. And as we drill up the PUDs, it's giving us more and more confidence that some of those probables and some of those possibles may move up the reserve category as we go forward. So we'll be looking at that in some detail, of course, at our midyear reserve report. When we looked at this -- at these fields in South Texas, we felt like they had pretty significant probable and possible reserve potential for us. We just never quantified that for anybody.

That does it for me. Thank you.

Zeke Loreto, Silver Lake Financial.

My questions were already asked, actually.

You've got another one, a new one?

(inaudible) just asking about noncore properties. Thank you.

With no further questions in the queue, I'd like to turn the call back to management for closing remarks.

Thanks very much for joining us. We appreciate it. If you have any other questions or comments, give us a call. We'll be around this afternoon. Thanks.

Thank you for your participation on today's conference. This does conclude your presentation. You may now disconnect. Have a good day.